Field of the Disclosure
The present disclosure generally relates to a cementing system for a riserless abandonment operation.
Description of the Related Art
FIGS. 1A-1C illustrate a prior art completed subsea well. A conductor string 3 may be driven into a floor if of the sea 1. The conductor string 3 may include a housing 3h and joints of conductor pipe 3p connected together, such as by threaded connections. Once the conductor string 3 has been set, a subsea wellbore 2 may be drilled into the seafloor if and extend into one or more upper formations 9u. A surface casing string 4 may be deployed into the wellbore 3. The surface casing string 4 may include a wellhead housing 4h and joints of casing 4c connected together, such as by threaded connections. The wellhead housing 4h may land in the conductor housing 3h during deployment of the surface casing string 4. The surface casing string 4 may be cemented 8s into the wellbore 2. Once the surface casing string 2 has been set, the wellbore 2 may be extended and an intermediate casing string 5 may be deployed into the wellbore. The intermediate casing string 5 may include a hanger 5h and joints of casing 5c connected together, such as by threaded connections. The intermediate casing string 5 may be cemented 8i into the wellbore 2.
Once the intermediate casing string 5 has been set, the wellbore 2 may be extended into and a hydrocarbon-bearing (i.e., crude oil and/or natural gas) reservoir 9r. The production casing string 6 may be deployed into the wellbore. The production casing string 6 may include a hanger 6h and joints of casing 6c connected together, such as by threaded connections. The production casing string 6 may be cemented 8p into the wellbore 2. Each casing hanger 5h, 6h may be sealed in the wellhead housing 4h by a packoff. The housings 3h, 4h and hangers 5h, 6h may be collectively referred to as a wellhead 10.
A production tree 15 may be connected to the wellhead 10, such as by a tree connector 13. The tree connector 13 may include a fastener, such as dogs, for fastening the tree to an external profile of the wellhead 10. The tree connector 13 may further include a hydraulic actuator and an interface, such as a hot stab, so that a remotely operated subsea vehicle (ROV) 20 (FIG. 2A) may operate the actuator for engaging the dogs with the external profile. The tree 15 may be vertical or horizontal. If the tree is vertical (not shown), it may be installed after a production tubing string 7 is hung from the wellhead 10. If the tree 15 is horizontal (as shown), the tree may be installed and then the production tubing string 7 may be hung from the tree 15. The tree 15 may include fittings and valves to control production from the wellbore 2 into a pipeline (not shown) which may lead to a production facility (not shown), such as a production vessel or platform.
The production tubing string 7 may include a hanger 7h and joints of production tubing 7t connected together, such as by threaded connections. The production tubing string 7 may further include a subsurface safety valve (SSV) 7v interconnected with the tubing joints 7t and a hydraulic conduit 7c extending from the valve 7v to the hanger 7h. The production tubing string 7 may further include a production packer 7p and the packer may be set between a lower end of the production tubing and the production casing string 6 to isolate an annulus 7a (aka the A annulus) formed therebetween from production fluid (not shown). The tree 15 may also be in fluid communication with the hydraulic conduit 7c. A lower end of the production casing string 6 may be perforated 11 to provide fluid communication between the reservoir 9r and a bore of the production tubing string 7. The production tubing string 7 may transport production fluid from the reservoir 9r to the production tree 15.
The tree 15 may include a head 12, the tubing hanger 7h, the tree connector 13, an internal cap 14, an external cap 16, an upper crown plug 17u, a lower crown plug 17b, a production valve 18p, one or more annulus valves 18u,b, and a face seal 19. The tree head 12, tubing hanger 7h, and internal cap 14 may each have a longitudinal bore extending therethrough. The tubing hanger 7h and head 12 may each have a lateral production passage formed through walls thereof for the flow of production fluid. The tubing hanger 7h may be disposed in the head bore. The tubing hanger 7h may be fastened to the head by a latch.
Once the reservoir 9r has been produced to depletion, the well must be abandoned. Conventionally, an abandonment operation includes cutting into the casings and filling the annuli with cement to seal the upper regions of the annuli. To achieve this, it is usual to use a semi-submersible drilling vessel (SSDV) which is located above the well and anchored in position. After removal of the cap 16 from the well, a unit including blow-out preventers and a riser is lowered and locked on to the wellhead. A tool string is run on pipe to sever or perforate the casing or casings. Weighted fluid is pumped into the well to provide a hydrostatic head to balance any possible pressure release when the casing is cut. The casing is then cut, and the annulus cemented. The cemented annulus is then pressure tested to ensure an adequate seal has been obtained. The casing is severed below the mud line and the casing hangers retrieved, and finally after removal from the well, the well is filled with cement. Whilst by this procedure satisfactory well abandonment can be achieved, it is expensive in terms of the equipment involved and the time taken which is often from seven to ten days per well.